xcel energy SPS_10Q_2007_Q3

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-Q
⌧ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT
OF 1934

For the quarterly period ended Sept. 30, 2007

or

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT
OF 1934

For the transition period from to

Commission File Number: 001-03789

Southwestern Public Service Company
(Exact name of registrant as specified in its charter)

New Mexico 75-0575400
(State or other jurisdiction of (I.R.S. Employer Identification No.)
incorporation or organization)

Tyler at Sixth,
Amarillo, Texas 79101
(Address of principal executive (Zip Code)
offices)

Registrant’s telephone number, including area code (303) 571-7511

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the
Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required
to file such reports), and (2) has been subject to such filing requirements for the past 90 days. ⌧ Yes No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer or a non-accelerated filer. See
definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

Non-Accelerated Filer ⌧
Large Accelerated Filer Accelerated Filer

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
No ⌧
Yes

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.

Class Outstanding at Oct. 29, 2007
Common Stock, $1 par value 100 shares

Southwestern Public Service Company meets the conditions set forth in General Instruction H (1)(a) and (b) of Form 10-Q
and is therefore filing this Form 10-Q with the reduced disclosure format specified in General Instruction H (2) to such Form
10-Q.

Table of Contents

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PART I - FINANCIAL INFORMATION

Item l. Financial Statements 3
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations 16
Item 4. Controls and Procedures 20

20
PART II - OTHER INFORMATION

Item 1. Legal Proceedings 20
Item 1A. Risk Factors 20
Item 6. Exhibits 20
SIGNATURES 21
Certifications Pursuant to Section 302
Certifications Pursuant to Section 906
Statement Pursuant to Private Litigation

This Form 10-Q is filed by Southwestern Public Service Co. (SPS). SPS is a wholly owned subsidiary of Xcel Energy Inc.
(Xcel Energy). Additional information on Xcel Energy is available on various filings with the Securities and Exchange
Commission (SEC).

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PART 1. FINANCIAL INFORMATION

Item 1. Financial Statements

SOUTHWESTERN PUBLIC SERVICE CO.
STATEMENTS OF INCOME (UNAUDITED)
(Thousands of Dollars)

Three Months Ended Nine Months Ended
Sept. 30, Sept. 30,
2007 2006 2007 2006

$ 471,521 $ 472,586 $ 1,238,544 $ 1,308,575
Operating revenues.............................................................

Operating expenses
Electric fuel and purchased power.................................... 339,041 333,401 899,962 937,694
Other operating and maintenance expenses...................... 49,515 39,509 149,707 138,244
Depreciation and amortization.......................................... 24,115 23,764 73,115 71,673
Taxes (other than income taxes) ....................................... 10,117 12,598 30,920 39,972
Total operating expenses .............................................. 422,788 409,272 1,153,704 1,187,583

48,733 63,314 84,840 120,992
Operating income ...............................................................

Interest and other income, net (see Note 9) ...................... 834 987 2,164 3,655
Allowance for funds used during construction — equity — 384 — 882

Interest charges and financing costs
Interest charges — includes other financing costs of $587,
$1,567, $1,762 and $4,669, respectively ...................... 14,119 13,105 40,871 40,714
Allowance for funds used during construction — debt .... (660) (685) (1,764) (2,061)
Total interest charges and financing costs .................... 13,459 12,420 39,107 38,653

Income before income taxes ................................................. 36,108 52,265 47,897 86,876
Income taxes......................................................................... 14,956 19,662 19,461 32,405
$ 21,152 $ 32,603 $ 28,436 $ 54,471
Net income...........................................................................

See Notes to Financial Statements

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STATEMENTS OF CASH FLOWS (UNAUDITED)

Nine Months Ended
Sept. 30,
2007 2006
Operating activities
Net income................................................................................................................. $ 28,436 $ 54,471
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization ............................................................................... 75,831 78,438
Deferred income taxes ........................................................................................... 6,700 (28,070)
Amortization of investment tax credits.................................................................. (188) (188)
Allowance for equity funds used during construction ........................................... — (882)
Net realized and unrealized hedging and derivative transactions .......................... 201 (827)
Changes in operating assets and liabilities:
Accounts receivable........................................................................................... (20,929) 35,707
Accrued unbilled revenues................................................................................. (50,234) 26,561
Recoverable electric energy costs ...................................................................... 63,756 44,200
Inventories ......................................................................................................... 1,197 (2,755)
Prepayments and other....................................................................................... 1,428 959
Accounts payable............................................................................................... (22,106) (22,792)
Net regulatory assets and liabilities ................................................................... (6,923) (4,664)
Other current liabilities ...................................................................................... (2,854) 11,482
Change in other noncurrent assets ......................................................................... (5,758) (12,374)
Change in other noncurrent liabilities .................................................................... (2,946) 3,547
Net cash provided by operating activities .......................................................... 65,611 182,813

Investing activities
Capital/construction expenditures.............................................................................. (101,584) (77,565)
Proceeds from sale of assets ...................................................................................... — 24,670
Allowance for equity funds used during construction ............................................... — 882
Investments in utility money pool arrangement......................................................... (95,000) (47,900)
Receipts from utility money pool arrangement.......................................................... 95,000 47,900
Other investments ...................................................................................................... 3,212 16
Net cash used in investing activities .................................................................. (98,372) (51,997)

Financing activities
Short-term debt repayments — net ............................................................................ (1,000) (85,000)
Borrowings under utility money pool arrangement ................................................... 459,000 324,300
Repayments under utility money pool arrangement .................................................. (459,000) (324,300)
Borrowings under 5-year unsecured credit facility .................................................... 125,000 —
Capital contributions from parent .............................................................................. 5,354 7,561
Dividends paid to parent ............................................................................................ (52,825) (59,495)
Net cash provided by (used in) financing activities ........................................... 76,529 (136,934)

Net increase (decrease) in cash and cash equivalents ................................................ 43,768 (6,118)
Cash and cash equivalents at beginning of period ..................................................... 297 9,407
Cash and cash equivalents at end of period ............................................................... $ 44,065 $ 3,289

Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized).................................................... $ 35,499 $ 29,300
Cash paid for income taxes (net of refunds received)................................................ 18,376 45,930

Supplemental disclosure of non-cash investing transactions:
Property, plant and equipment additions in accounts payable ................................... $ 3,494 $ 1,525

See the Notes to Financial Statements

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BALANCE SHEETS (UNAUDITED)

Sept. 30, 2007 Dec. 31, 2006
ASSETS
Current assets:
Cash and cash equivalents........................................................................................................ $ 44,065 $ 297
Accounts receivable, net of allowance for bad debts of $2,875 and $2,686, respectively ........ 80,108 56,616
Accounts receivable from affiliates.......................................................................................... 6,245 8,808
Accrued unbilled revenues ....................................................................................................... 113,039 62,805
Recoverable electric energy costs............................................................................................. 19,344 83,100
Materials and supplies inventories ........................................................................................... 16,935 17,547
Fuel inventories........................................................................................................................ 3,510 4,095
Derivative instruments valuation.............................................................................................. 8,926 8,926
Prepayments and other ............................................................................................................. 4,899 8,326
Total current assets .............................................................................................................. 297,071 250,520
Property, plant and equipment, at cost:
Electric utility plant.................................................................................................................. 3,466,348 3,401,108
Construction work in progress.................................................................................................. 77,151 53,051
Total property, plant and equipment .................................................................................... 3,543,499 3,454,159
Less accumulated depreciation................................................................................................. (1,520,067) (1,462,787)
Net property, plant and equipment....................................................................................... 2,023,432 1,991,372
Other assets:
Prepaid pension asset ............................................................................................................... 114,274 106,193
Regulatory assets...................................................................................................................... 159,255 163,067
Other investments..................................................................................................................... 4,643 5,846
Other ........................................................................................................................................ 7,227 7,890
Total other assets ................................................................................................................. 373,107 377,398
Total assets........................................................................................................................... $ 2,693,610 $ 2,619,290

LIABILITIES AND EQUITY
Current liabilities:
Short-term debt......................................................................................................................... $ 50,000 $ 51,000
Accounts payable ..................................................................................................................... 139,121 159,672
Accounts payable to affiliates .................................................................................................. 14,460 14,783
Accrued interest ....................................................................................................................... 19,045 12,099
Dividends payable to parent ..................................................................................................... 16,284 18,581
Taxes accrued........................................................................................................................... 23,272 33,122
Deferred income taxes.............................................................................................................. 1,490 6,849
Other ........................................................................................................................................ 24,708 24,944
Total current liabilities......................................................................................................... 292,737 325,357
Deferred credits and other liabilities:
Deferred income taxes.............................................................................................................. 454,302 451,108
Regulatory liabilities ................................................................................................................ 139,427 143,789
Pension and employee benefit obligations ............................................................................... 53,980 54,647
Asset retirement obligations ..................................................................................................... 4,526 4,341
Deferred investment tax credits................................................................................................ 3,027 3,215
Other ........................................................................................................................................ 6,780 3,329
Total deferred credits and other liabilities............................................................................ 723,291 724,616
Commitments and contingencies (see Note 5)..............................................................................
Capitalization:
Long-term debt......................................................................................................................... 899,001 773,903
Common stock – authorized 200 shares of $1.00 par value, outstanding 100 shares — —
Additional paid in capital ......................................................................................................... 483,622 478,269
Retained earnings ..................................................................................................................... 300,574 323,008
Accumulated other comprehensive loss ................................................................................... (5,615) (5,863)
Total common stockholder’s equity..................................................................................... 778,581 795,414
Total liabilities and equity.................................................................................................... $ 2,693,610 $ 2,619,290

See the Notes to Financial Statements

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NOTES TO FINANCIAL STATEMENTS

In the opinion of management, the accompanying unaudited financial statements contain all adjustments necessary to present
fairly the financial position of SPS as of Sept. 30, 2007, and Dec. 31, 2006; the results of its operations for the three and nine
months ended Sept. 30, 2007 and 2006; and its cash flows for the nine months ended Sept. 30, 2007 and 2006. Due to the
seasonality of electric sales of SPS, interim results are not necessarily an appropriate base from which to project annual
results.

1. Significant Accounting Policies

Except to the extent updated or described below, the significant accounting policies set forth in Note 1 to the financial
statements in SPS’ Annual Report on Form 10-K for the year ended Dec. 31, 2006 appropriately represent, in all material
respects, the current status of accounting policies and are incorporated herein by reference.

Income Taxes — Consistent with prior periods and upon adoption of Financial Accounting Standard Board (FASB)
Interpretation No. 48 — “Accounting for Uncertainty in Income Taxes — an interpretation of FASB Statement No. 109”,
SPS records interest and penalties related to income taxes as interest charges in the Statements of Income.

Reclassifications — Certain amounts in the Statements of Cash Flows have been reclassified from prior-period presentation
to conform to the 2007 presentation. The reclassifications reflect the presentation of unbilled revenues, recoverable purchased
electric energy costs and regulatory assets and liabilities as separate items rather than components of other assets and other
liabilities within net cash provided by operating activities. In addition, activity related to derivative transactions have been
combined into net realized and unrealized hedging and derivative transactions. These reclassifications did not affect total net
cash provided by (used in) operating, investing or financing activities within the Statements of Cash Flows.

2. Recently Issued Accounting Pronouncements

Fair Value Measurements (Statement of Financial Accounting Standards (SFAS) 157) — In September 2006, the FASB
issued SFAS 157, which provides a single definition of fair value, together with a framework for measuring it, and requires
additional disclosure about the use of fair value to measure assets and liabilities. SFAS 157 also emphasizes that fair value is
a market-based measurement, and sets out a fair value hierarchy with the highest priority being quoted prices in active
markets. Fair value measurements are disclosed by level within that hierarchy. SFAS 157 is effective for financial statements
issued for fiscal years beginning after Nov. 15, 2007. SPS is evaluating the impact of SFAS 157 on its financial condition and
results of operations.

The Fair Value Option for Financial Assets and Financial Liabilities - Including an Amendment of FASB Statement No.
115 (SFAS 159) — In February 2007, the FASB issued SFAS 159, which provides companies with an option to measure, at
specified election dates, many financial instruments and certain other items at fair value that are not currently measured at
fair value. A company that adopts SFAS 159 will report unrealized gains and losses on items, for which the fair value option
has been elected, in earnings at each subsequent reporting date. This statement also establishes presentation and disclosure
requirements designed to facilitate comparisons between entities that choose different measurement attributes for similar
types of assets and liabilities. This statement is effective for fiscal years beginning after Nov. 15, 2007. SPS is evaluating the
impact of SFAS 159 on its financial condition and results of operations.

3. Income Taxes

Accounting for Uncertainty in Income Taxes — an interpretation of FASB Statement No. 109 (FIN 48) — In July 2006,
the FASB issued FIN 48, which prescribes how a company should recognize, measure, present and disclose uncertain tax
positions that the company has taken or expects to take in its income tax returns. FIN 48 requires that only income tax
benefits that meet the “more likely than not” recognition threshold be recognized or continue to be recognized on its effective
date. As required, SPS adopted FIN 48 as of Jan. 1, 2007 and the initial derecognition amounts were reported as a cumulative
effect of a change in accounting principle. The cumulative effect of the change, which is reported as an adjustment to the
beginning balance of retained earnings, was not material. Following implementation, the ongoing recognition of changes in
measurement of uncertain tax positions will be reflected as a component of income tax expense.

SPS is a member of the Xcel Energy affiliated group that files consolidated income tax returns. Xcel Energy has been audited
by the Internal Revenue Service (IRS) through tax year 2003, with a limited exception for 2003 research tax credits. The IRS
commenced an examination of Xcel Energy’s federal income tax returns for 2004 and 2005 (and research credits for 2003) in
the third quarter of 2006, and that examination is anticipated to be complete by March 31, 2008. As of Sept. 30, 2007, the

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IRS had not proposed any material adjustments to tax years 2003 through 2005. The statute of limitations applicable to Xcel
Energy’s 2000 through 2002 federal income tax returns expired as of June 30, 2007.

SPS is also currently under examination by the state of Texas for tax years 2003 through 2005. A $2.0 million adjustment has
been proposed by the state of Texas in their audit of these years. As of Sept. 30, 2007, SPS’ earliest open tax years in which
an audit can be initiated by state taxing authorities under applicable statutes of limitations is 2003.

The amount of unrecognized tax benefits was $5.0 million and $5.8 million on Jan. 1, 2007 and Sept. 30, 2007, respectively.
Of these amounts, $0.2 million and $0.1 million were offset against the tax benefits associated with net tax credit carryovers
as of Jan. 1, 2007 and Sept. 30, 2007, respectively.

Included in the unrecognized tax benefit balance was $0.2 million and $0.3 million of tax positions on Jan.1, 2007 and Sept.
30, 2007, respectively, which if recognized would affect the annual effective tax rate. In addition the unrecognized tax benefit
balance included $4.8 million and $5.5 million of tax positions on Jan. 1, 2007 and Sept. 30, 2007, respectively, for which the
ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductibility. A change in
the period of deductibility would not affect the effective tax rate but would accelerate the payment of cash to the taxing
authority to an earlier period. The increase in the unrecognized tax benefit balance of $0.9 million from July 1, 2007 to Sept.
30, 2007, was due to the addition of similar uncertain tax positions relating to third quarter activity and the resolution of
certain federal audit matters.

SPS’ amount of unrecognized tax benefits could significantly change in the next 12 months as the IRS and state tax audits
progress. However, at this time due to the nature of the audit process, it is not reasonably possible to estimate a range of the
possible change.

The interest expense liability related to unrecognized tax benefits on Jan. 1, 2007, was not material. The change in the interest
expense liability from Jan. 1, 2007, to Sept. 30, 2007, was not material. No amounts were accrued for penalties as of Sept. 30,
2007.

4. Rate Matters

Pending and Recently Concluded Regulatory Proceedings — Federal Energy Regulatory Commission (FERC)

Wholesale Rate Complaints — In November 2004, Golden Spread Electric, Lyntegar Electric, Farmer’s Electric, Lea
County Electric, Central Valley Electric and Roosevelt County Electric, wholesale cooperative customers of SPS, filed a rate
complaint at the FERC. The complaint alleged that SPS’ rates for wholesale service were excessive and that SPS had
incorrectly calculated monthly fuel cost adjustments contained in SPS’ wholesale rate schedules. Among other things, the
complainants asserted that SPS was not properly calculating the fuel costs that are eligible for recovery and that SPS had
inappropriately allocated average fuel and purchased power costs to its other wholesale customers, effectively raising the fuel
costs charges to complainants. Cap Rock Energy Corporation (Cap Rock), a full-requirements customer, Public Service
Company of New Mexico (PNM) and Occidental Permian Ltd. and Occidental Power Marketing, L.P. (Occidental)
intervened in the proceeding.

On May 24, 2006, a FERC administrative law judge (ALJ) issued an initial recommended decision in the proceeding. The
FERC will review the initial recommendation and issue a final order. SPS and others have filed exceptions to the ALJ’s
initial recommendation. The FERC’s order may or may not follow any of the ALJ’s recommendation. In the recommended
decision, the ALJ found that SPS should recalculate its wholesale fuel and purchased economic energy cost adjustment clause
(FCAC) billings for the period beginning Jan. 1, 1999, to reduce the fuel and purchased power costs recovered from the
complaining customers by allocating incremental fuel costs incurred by SPS in making wholesale sales of system firm
capacity and associated energy to other firm customers served under market-based rates during this period based on the view
that such sales should be treated as opportunity sales.

SPS believes the ALJ erred on significant and material issues that contradict FERC policy or rules of law. Specifically, SPS
believes, based on FERC rules and precedent, that it has appropriately applied its FCAC tariff to the proper classes of
customers. These firm market-based sales were of a long-term duration under FERC precedent and were made from SPS’
entire system. Accordingly, SPS believes that the ALJ erred in concluding that these transactions were opportunity sales,
which require the assignment of incremental costs.

The FERC has approved system average cost allocation treatment in previous filings by SPS for sales having similar service
characteristics and previously accepted for filing certain of the challenged agreements with average fuel cost pricing.

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Moreover, SPS believes that the ALJ’s recommendation constituted a violation of the filed rate doctrine in that it effectively
results in a retroactive amendment to the SPS FERC-approved FCAC tariff provisions. Under existing regulations, the FERC
may modify a previously approved FCAC on a prospective basis. Accordingly, SPS believes it has applied its FCAC
correctly and has sought review of the recommended decision by the FERC by filing a brief on the exceptions.

SPS believes it should ultimately prevail in this proceeding, however, if the FERC were to adopt the majority of the ALJ’s
recommendations, SPS’ refund exposure could be approximately $50 million, based on an evaluation of all sales made from
Jan. 1, 1999 to Dec. 31, 2006. SPS has entered into settlement discussions with the wholesale cooperative customers. As of
Sept. 30, 2007, based upon management’s estimate of this potential liability, SPS believes the appropriate accrual has been
recorded for this matter. Additionally, SPS has entered into settlement discussions with the wholesale cooperative customers.
As of Sept. 30, 2007, based upon management’s estimate of this potential liability, SPS believes the appropriate accrual has
been recorded for this matter.

In July and September 2007, Golden Spread and SPS filed a joint motion requesting the FERC to defer the final order while
the cooperative customers negotiate the complaint case. The case is still pending final FERC action.

Wholesale Power Base Rate Application — On Dec. 1, 2005, SPS filed for a $2.5 million increase in wholesale power rates
to certain electric cooperatives. On Jan. 31, 2006, the FERC conditionally accepted the proposed rates for filing, and the $2.5
million power rate increase became effective on July 1, 2006, subject to refund. The FERC also set the rate increase request
for hearing and settlement judge procedures. On Sept. 7, 2006, an offer of settlement with respect to the five full-
requirements customers was filed for approval and on Sept. 19, 2006, the offer of settlement with respect to PNM was filed
for approval. On Sept. 20, 2007, the FERC accepted the settlement with the full-requirements customers. The PNM
settlement is still pending before the FERC.

Golden Spread Electric Cooperative, SPS’ partial requirements wholesale customer, did not settle and hearings were set for
the rate disputes raised by Golden Spread. Subsequent to filing rebuttal testimony, on March 29, 2007, SPS and Golden
Spread entered into additional settlement negotiations. The current hearing schedule has been postponed. The FERC has
appointed a settlement judge to facilitate negotiations.

Pending and Recently Concluded Regulatory Proceedings — Public Utility Commission of Texas (PUCT)

Texas Retail Base Rate And Fuel Reconciliation Case — On May 31, 2006, SPS filed a Texas retail electric rate case
requesting an increase in annual revenues of approximately $48 million. The rate filing was based on a historical test year, an
electric rate base of $943 million, a requested ROE of 11.6 percent and a common equity ratio of 51.1 percent.

In addition, SPS submitted a fuel reconciliation filing, which requested approval of approximately $957 million of Texas-
jurisdictional fuel and purchased power costs for 2004 through 2005. As a part of the fuel reconciliation case, fuel and
purchased energy costs were reviewed.

On March 27, 2007, SPS and various intervenors filed a unanimous stipulation agreement related to the Texas retail rate case
as well as the fuel reconciliation portion of the proceeding. The agreement includes the following terms:

• The settlement provides for an annual base rate increase of $23 million, or approximately 3 percent.

• The settlement disallows approximately $27 million of SPS’ 2004 and 2005 fuel expense.

• An additional $2.3 million will be deducted from SPS’ next fuel reconciliation filing to be made in 2008, associated
with the 2006-2007 fuel reconciliation period.

• All of SPS’ existing long-term firm and interruptible capacity wholesale sales are assigned system average costs for
purposes of Texas retail ratemaking, except for sales to El Paso Electric (EPE), which is determined by the PUCT
separately.

• The settlement also creates standards for cost assignment that would apply to future wholesale sale transactions, and
establishes margin sharing of market based wholesale demand revenues.

• If SPS files a general rate case in 2008, the settlement would allow for an interim rate increase associated with a
purchased power agreement with Lea Power Partners of approximately $1.5 million per month from the date of

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commercial operations. Interim rates would be subject to a true-up based on the outcome of the rate case proceeding and
actual capacity costs incurred.

An estimated settlement allowance and reserve was established in 2006 and prior periods, which approximated the settled
amounts of previously deferred or recovered fuel expense.

On March 27, 2007, the ALJ approved SPS’ request to implement the $23 million base rate increase, effective April 2007, on
an interim basis until the PUCT acts on the stipulation. The $23 million base rate increase includes approximately $14
million of coal cost that was previously recovered through the fuel cost recovery mechanism, and approximately $6.2 million
that results from interruptible customers converting to firm service.

On July 27, 2007, the PUCT issued a written order adopting the settlement and assigning incremental costs to the EPE sale.
The effect of this decision under the terms of the settlement is an additional $3 million in fuel costs assigned to EPE, which
SPS will not recover either through its FCA or its contract. For 2008, this amount will reach $6.3 million. SPS has previously
given notice to EPE to terminate the agreement based on a regulatory provision and Xcel Energy expects that the termination
will be effective in 2009.

Pending and Recently Concluded Regulatory Proceedings — New Mexico Public Regulation Commission (NMPRC)

New Mexico Fuel Factor Continuation Filing — On Aug. 18, 2005, SPS filed with the NMPRC requesting continuation of
the use of SPS’ fuel and purchased power cost adjustment clause (FPPCAC) and current monthly factor cost recovery
methodology. This filing was required by NMPRC rule.

Testimony was filed in the case by staff and intervenors objecting to SPS’ assignment of system average fuel costs to certain
wholesale sales and the inclusion of certain purchased power capacity and energy payments in the FPPCAC. The testimony
also proposed limits on SPS’ future use of the FPPCAC. Related to these issues some intervenors requested disallowances for
past periods, which in the aggregate total approximately $45 million. This claim was for the period from Oct. 1, 2001 through
May 31, 2005 and does not include the value of incremental cost assigned for wholesale transactions from that date forward.
Other issues in the case include the treatment of renewable energy certificates and sulfur dioxide (SO2) allowance credit
proceeds in relation to SPS’ New Mexico retail fuel and purchased power recovery clause.

On May 2, 2007, the hearing examiner issued his recommended decision in which he determined the following:

• The NMPRC is barred from granting the retroactive refunds or financial penalties requested by the parties.

• The issues related to the assignment of system average fuel cost to SPS’ firm wholesale sales, subsequent to March 7,
2006, should be litigated in SPS’ next rate case which was filed in July 2007, or in a separate parallel proceeding with
the results to be incorporated into the next rate case.

• The NMPRC lacked legal authority to apply any change in cost assignment methodology retroactively until such date
that SPS was put on notice of any concern with its longstanding assignment practice.

• March 7, 2006 was the first time that SPS was put on notice with respect to any change in New Mexico’s assignment
practice.

• The future litigation recommendation would determine both the proper allocation and assignment of fixed and fuel costs
and examine the prudence of SPS’ firm wholesale contracts and affiliate transactions related to those wholesale sales.

• Charges collected through the FPPCAC since March 7, 2006, should be subject to refund pending further order of the
NMPRC. The hearing examiner also noted that specific allegations regarding affiliate transactions could also be
resolved in these proceedings.

Under the recommended decision, SPS would also be ordered to refund approximately $1.6 million of long-term purchased
power capacity costs that it acknowledged were erroneously collected through the FPPCAC. SPS would be authorized to
continue its use of the FPPCAC pending a final order in the next rate case. The hearing examiner also determined that no
action was required on renewable energy certificates and that SPS should seek a determination of proper treatment of SO2
allowances in a separate proceeding. Although there is no deadline for NMPRC action, SPS expects the NMPRC will act
during the fourth quarter of 2007. As of Sept. 30, 2007, based upon management’s estimate of this potential liability, SPS
believes the appropriate accrual has been recorded for this matter.

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New Mexico Electric Rate Case - On July 30, 2007, SPS filed with the NMPRC requesting a New Mexico retail electric
general rate increase of $17.3 million annually or a 6.6 percent increase. The rate filing is based on a 2006 calendar year base
period adjusted for known and measurable changes and includes a requested rate of return on equity of 11.0 percent, an
electric rate base of approximately $307.3 million allocated to the New Mexico retail jurisdiction and an equity ratio of 51.2
percent. The NMPRC suspended the requested effective date for an additional nine months beyond the requested effective
date. Intervenor testimony is due Dec. 21, 2007 and hearings are scheduled for Jan. 28-Feb. 1, 2008. A decision on the
request is expected in the second quarter of 2008, and final rates are expected to be implemented in mid-2008.

Investigation of SPS Participation in SPP - On Oct. 16, 2007, the PRC issued an order initiating an investigation to consider
the prudence and reasonableness of SPS’ participation in the Southwest Power Pool, Inc. (SPP) regional transmission
organization (RTO). The investigation will consider the costs and benefits of RTO participation to SPS customers in New
Mexico. The order required SPS to file direct testimony no later than 75 days after the completion of the hearing in the New
Mexico electric rate case.

5. Commitments and Contingent Liabilities

Except to the extent noted below, the circumstances set forth in Note 10 and 11 to the financial statements in SPS’ Annual
Report on Form 10-K for the year ended Dec. 31, 2006 and Note 4 to the financial statements in this Quarterly Report on
Form 10-Q, appropriately represent, in all material respects, the current status of commitments and contingent liabilities and
are incorporated herein by reference. The following include unresolved contingencies that are material to SPS’ financial
position.

Environmental Contingencies

SPS has been, or is currently, involved with the cleanup of contamination from certain hazardous substances at several sites.
In many situations, SPS believes it will recover some portion of these costs through insurance claims. Additionally, where
applicable, SPS is pursuing, or intends to pursue, recovery from other potentially responsible parties and through the rate
regulatory process. New and changing federal and state environmental mandates can also create added financial liabilities for
SPS, which are normally recovered through the rate regulatory process. To the extent any costs are not recovered through the
options listed above, SPS would be required to recognize an expense.

Site Remediation — SPS must pay all or a portion of the cost to remediate sites where past activities of SPS and some other
parties have caused environmental contamination. At Sept. 30, 2007, SPS was a party to third party and other sites, such as
landfills, to which SPS is alleged to be a potentially responsible party (PRP) that sent hazardous materials and wastes.

SPS records a liability when enough information is obtained to develop an estimate of the cost of environmental remediation
and revises the estimate as information is received. The estimated remediation cost may vary materially.

To estimate the cost to remediate these sites, assumptions are made when facts are not fully known. For instance,
assumptions may be made about the nature and extent of site contamination, the extent of required cleanup efforts, costs of
alternative cleanup methods and pollution-control technologies, the period over which remediation will be performed and
paid for, changes in environmental remediation and pollution-control requirements, the potential effect of technological
improvements, the number and financial strength of other PRPs and the identification of new environmental cleanup sites.

Estimates are revised as facts become known. At Sept. 30, 2007, the liability for the cost of remediating these sites was
estimated to be $0.1 million. Some of the cost of remediation may be recovered from:

• Insurance coverage;

• Other parties that have contributed to the contamination; and

• Customers.

Neither the total remediation cost nor the final method of cost allocation among all PRPs of the unremediated sites has been
determined. Estimates have been recorded for SPS’ future costs for these sites.

10

Third Party and Other Environmental Site Remediation

Asbestos Removal — Some of SPS’ facilities contain asbestos. Most asbestos will remain undisturbed until the facilities that
contain it are demolished or renovated. SPS has recorded an estimate for final removal of the asbestos as an asset retirement
obligation. See additional discussion of asset retirement obligations in Note 11 to the SPS Annual Report on Form 10-K for
the year ended Dec. 31, 2006. It may be necessary to remove some asbestos to perform maintenance or make improvements
to other equipment. The cost of removing asbestos as part of other work is immaterial and is recorded as incurred as
operating expenses for maintenance projects, capital expenditures for construction projects or removal costs for demolition
projects.

Cunningham and Maddox Station Groundwater — Cunningham Station is a natural gas-fired power plant constructed in
the 1960’s by SPS and has 28 water wells installed on its water rights. The well field provides water for boiler makeup,
cooling water and potable water. Following an acid release in 2002, groundwater samples revealed elevated concentrations of
inorganic salt compounds not related to the release. The contamination was identified in wells located near the plant
buildings. The source of contamination is thought to be leakage from ponds that receive blow down water from the plant.

In response to a request by the New Mexico Environment Department (NMED), SPS prepared a corrective action plan to
address the groundwater contamination. Under the plan submitted to the NMED, SPS agreed to control leakage from the
plant blow down ponds through construction of a new lined pond, additional irrigation areas to minimize percolation, and
installation of additional wells to monitor groundwater quality. On June 23, 2005, NMED issued a letter approving the
corrective action plan. The action plan was subject to continued compliance with New Mexico regulations and oversight by
the NMED. The Cunningham wastewater management project has been completed at a final cost of $3.5 million. Upon
completion of the project, NMED finalized the wastewater permit. SPS began the implementation of a similar process at the
Maddox Station in 2007. The permitting process for Maddox Station has begun and is estimated to cost approximately $1.3
million through 2008 and will be capitalized or expensed as incurred.

Clean Air Interstate Rule - In March 2005, the Environmental Protection Agency (EPA) issued the Clean Air Interstate Rule
(CAIR) to further regulate SO2 and nitrogen oxide (NOx) emissions. The objective of CAIR is to cap emissions of SO2 and
NOx in the eastern United States, including Minnesota, Texas and Wisconsin, which are within Xcel Energy’s service
territory. Xcel Energy generating facilities in other states are not affected. CAIR addresses the transportation of fine
particulates, ozone and emission precursors to nonattainment downwind states. CAIR has a two-phase compliance schedule,
beginning in 2009 for NOx and 2010 for SO2, with a final compliance deadline in 2015 for both emissions. Under CAIR,
each affected state will be allocated an emissions budget for SO2 and NOX that will result in significant emission reductions.
It will be based on stringent emission controls and forms the basis for a cap-and-trade program. State emission budgets or
caps decline over time. States can choose to implement an emissions reduction program based on the EPA’s proposed model
program, or they can propose another method, which the EPA would need to approve.

On July 11, 2005, SPS, the City of Amarillo, Texas and Occidental Permian LTD filed a lawsuit against the EPA and a
request for reconsideration with the agency to exclude West Texas from the CAIR. El Paso Electric Co. joined in the request
for reconsideration. Xcel Energy and SPS advocated that West Texas should be excluded from CAIR because it does not
contribute significantly to nonattainment with the fine particulate matter standards in any downwind jurisdiction.

On March 15, 2006, the EPA denied the petition for reconsideration. On June 27, 2006, Xcel Energy and the other parties
filed a petition for review of the denial of the petition for reconsideration, as well as a petition for review of the Federal
Implementation Plan, with the D.C. Court of Appeals. Pursuant to the court’s scheduling order, briefing has been finalized,
but no court date has been set to hear oral arguments.

Under CAIR’s cap-and-trade structure, SPS can comply through capital investments in emission controls or purchase of
emission “allowances” from other utilities making reductions on their systems. Based on the preliminary analysis of various
scenarios of capital investment and allowance purchase, SPS currently believes that following the installation of low NOx
burners on Harrington 3 in 2006, additional capital investments, estimated at $12 million, will be remaining for NOx controls
in the SPS region. Purchases of NOx allowances in the first phase are estimated at $1.4 million. Annual purchases of SO2
allowances are estimated in the range of $13 million to $25 million each year, beginning in 2012 for phase I, based on
allowance costs and fuel quality as of March 2007.

These cost estimates represent one potential scenario on complying with CAIR, if West Texas is not excluded. There is
uncertainty concerning implementation of CAIR. States are required to develop implementation plans within 18 months of
the issuance of the new rules and have a significant amount of discretion in the implementation details. Legal challenges to

11

CAIR rules could alter their requirements and/or schedule. The uncertainty associated with the final CAIR rules makes it
difficult to project the ultimate amount and timing of capital expenditures and operating expenses.

While SPS expects to comply with the new rules through a combination of additional capital investments in emission controls
at various facilities and purchases of emission allowances, it is continuing to review the alternatives. Xcel Energy believes
the cost of any required capital investment or allowance purchases will be recoverable from customers.

Clean Air Mercury Rule — In March 2005, the EPA issued the Clean Air Mercury Rule (CAMR), which regulates mercury
emissions from power plants for the first time. The EPA’s CAMR uses a national cap-and-trade system, where compliance
may be achieved by either adding mercury controls or purchasing allowances or a combination of both and is designed to
achieve a 70 percent reduction in mercury emissions. It affects all coal- and oil-fired generating units across the country that
are greater than 25 MW. Compliance with this rule occurs in two phases, with the first phase beginning in 2010 and the
second phase in 2018. The Texas Commission on Environmental Quality (TCEQ) has adopted by reference the EPA model
program. States will be allocated mercury allowances based on coal type and their baseline heat input relative to other states.
Each electric generating unit will be allocated mercury allowances based on its percentage of total coal heat input for the
state.

Under CAMR, SPS can comply through capital investments in emission controls or purchase of emission “allowances” from
other utilities making reductions on their systems. SPS’ preliminary analysis for phase I compliance suggests capital costs of
approximately $14.5 million and increased operating and maintenance expenses of approximately $7.9 million, beginning in
2010. Testing at Harrington Station near Amarillo is complete pending a final report and additional testing at Tolk Station is
planned during the fourth quarter of 2007 to confirm these costs or determine whether different measures will be necessary,
which could result in higher costs. Additional costs will be incurred to meet phase II requirements in 2018.

Regional Haze Rules — On June 15, 2005, the EPA finalized amendments to the July 1999 regional haze rules. These
amendments apply to the provisions of the regional haze rule that require emission controls, known as best available retrofit
technology (BART), for industrial facilities emitting air pollutants that reduce visibility by causing or contributing to regional
haze. Some of SPS’ generating facilities will be subject to BART requirements. Some of these facilities are located in regions
where CAIR is effective. The TCEQ has determined that facilities may use CAIR as a substitute for BART for NOx and SO2.
If West Texas is excluded from CAIR by the D.C. Court of Appeals, then these facilities will be subject to BART
requirements for NOx, SO2, and particulate matter. Due to the uncertainties of the litigation outcome, SPS is not able to
estimate the cost impact at this time.

Legal Contingencies

In the normal course of business, SPS is party to routine claims and litigation arising from prior and current operations. SPS
is actively defending these matters and has recorded a liability related to the probable cost of settlement or other disposition,
when it can be reasonably estimated.

Carbon Dioxide Emissions Lawsuit — On July 21, 2004, the attorneys general of eight states and New York City, as well as
several environmental groups, filed lawsuits in U.S. District Court for the Southern District of New York against five
utilities, including Xcel Energy, to force reductions in carbon dioxide (CO2) emissions. Although SPS is not named as a party
to this litigation, the requested relief that Xcel Energy cap and reduce its CO2 emissions could have a material adverse effect
on SPS. The other utilities include American Electric Power Co., Southern Co., Cinergy Corp. and Tennessee Valley
Authority. CO2 is emitted whenever fossil fuel is combusted, such as in automobiles, industrial operations and coal- or
natural gas-fired power plants. The lawsuits allege that CO2 emitted by each company is a public nuisance as defined under
state and federal common law because it has contributed to global warming. The lawsuits do not demand monetary damages.
Instead, the lawsuits ask the court to order each utility to cap and reduce its CO2 emissions. In October 2004, Xcel Energy
and the other defendants filed a motion to dismiss the lawsuit. On Sept. 19, 2005, the judge granted the motion to dismiss on
constitutional grounds. Plaintiffs filed an appeal to the Second Circuit Court of Appeals. On June 21, 2007 the Second Circuit
Court of Appeals issued an order requesting the parties to file a letter brief regarding the impact of the United States Supreme
Court’s decision in Massachusetts v. EPA, 127 S.Ct. 1438 (April 2, 2007) on the issues raised by the parties on appeal.
Among other things, in its decision in Massachusetts v. EPA, the United States Supreme Court held that CO2 emissions are a
“ pollutant” subject to regulation by the EPA under the Clean Air Act. In response to the request of the Second Circuit Court
of Appeals, the defendant utilities filed a letter brief on July 6, 2007, stating the position that the United States Supreme
Court’s decision supports the arguments raised by the utilities on appeal. It is unknown when the Second Circuit Court of
Appeals will rule on the appeal.

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Lamb County Electric Cooperative - On July 24, 1995, Lamb County Electric Cooperative, Inc. (LCEC) petitioned the
PUCT for a cease and desist order against SPS alleging that SPS was unlawfully providing service to oil field customers in
LCEC’s certificated area. On May 23, 2003, the PUCT issued an order denying LCEC’s petition based on its determination
that SPS was granted a certificate in 1976 to serve the disputed customers. LCEC appealed the decision to the District Court
in Travis County, Texas and on Aug. 12, 2004, the District Court affirmed the decision of the PUCT. On Sept. 9, 2004,
LCEC appealed the District Court’s decision to the Court of Appeals for the Third Supreme Judicial District of the state of
Texas, which appeal is currently pending. Oral arguments in the case were heard March 23, 2005. SPS is awaiting the Court
of Appeals decision.

On Oct. 18, 1996, LCEC filed a suit for damages against SPS in the District Court in Lamb County, Texas, based on the same
facts as alleged in its petition for a cease and desist order at the PUCT. This suit has been dormant since it was filed, awaiting
a final determination at the PUCT of the legality of SPS providing electric service to the disputed customers. The PUCT
order of May 23, 2003, found that SPS was legally serving the disputed customers thus collaterally determining the issue of
liability contrary to LCEC’s position in the suit. An adverse ruling on the appeal of the May 23, 2003 PUCT order could
result in a re-determination of the legality of SPS’ service to the disputed customers.

Comer vs. Xcel Energy Inc. et al. — On April 25, 2006, Xcel Energy received notice of a purported class action lawsuit filed
in United States District Court for the Southern District of Mississippi. Although SPS is not named as a party to this
litigation, if the litigation ultimately results in an unfavorable outcome for Xcel Energy, it could have a material adverse
effect on SPS. The lawsuit names more than 45 oil, chemical and utility companies, including Xcel Energy, as defendants
and alleges that defendants’ CO2 emissions “were a proximate and direct cause of the increase in the destructive capacity of
Hurricane Katrina.” Plaintiffs allege in support of their claim, several legal theories, including negligence and public and
private nuisance and seek damages related to the loss resulting from the hurricane. Xcel Energy believes this lawsuit is
without merit and intends to vigorously defend itself against these claims. On July 19, 2006, Xcel Energy filed a motion to
dismiss the lawsuit in its entirety. On Aug. 30, 2007, the court dismissed the lawsuit in its entirety against all defendants on
constitutional grounds. On Sept. 17, 2007, plaintiffs filed a notice of appeal to the Fifth Circuit.
6. Short-Term Borrowings and Other Financing Instruments
As of Sept. 30, 2007, SPS had $50.0 million of short-term debt outstanding at a weighted average interest rate of 5.43
percent.

7. Long-Term Borrowings and Other Financing Instruments
On Aug. 29, 2007, SPS borrowed $125 million against its $250 million five-year unsecured credit facility. The weighted
average interest rate on the borrowing was 5.91 percent. The borrowing was repaid on Oct. 1, 2007.
8. Derivative Valuation and Financial Impacts
SPS uses a number of different derivative instruments in connection with its utility commodity price, interest rate, and limited
short-term wholesale and commodity trading activities, including forward contracts, futures, swaps and options.
All derivative instruments not qualifying for the normal purchases and normal sales exception, as defined by SFAS 133-
”Accounting for Derivative Instruments and Hedging Activities,” as amended (SFAS 133), are recorded at fair value. The
presentation of these derivative instruments is dependent on the designation of a qualifying hedging relationship. The
adjustment to fair value of derivative instruments not designated in a qualifying hedging relationship is reflected in current
earnings or as a regulatory balance.
SPS records the fair value of its derivative instruments in its Balance Sheets as separate line items identified as Derivative
Instruments Valuation in both current and noncurrent assets and liabilities.
Qualifying hedging relationships are designated as either a hedge of a forecasted transaction or future cash flow (cash flow
hedge), or a hedge of a recognized asset, liability or firm commitment (fair value hedge). The types of qualifying hedging
transactions that SPS is currently engaged in are discussed below.
Cash Flow Hedges
SPS enters into derivative instruments to manage variability of future cash flows from changes in commodity prices and
interest rates.
As of Sept. 30, 2007, SPS had no commodity-related contracts classified as cash flow hedges.

13

SPS enters into various instruments that effectively fix the interest payments on certain floating rate debt obligations or
effectively fix the yield or price on a specified benchmark interest rate for a specific period. These derivative instruments are
designated as cash flow hedges for accounting purposes, and the change in the fair value of these instruments is recorded as a
component of Other Comprehensive Income.

As of Sept. 30, 2007, SPS had net losses of approximately $0.7 million in Accumulated Other Comprehensive Income related
to interest rate cash flow hedge contracts that are expected to be recognized in earnings during the next 12 months.
Gains or losses on hedging transactions for the sales of energy or energy-related products are primarily recorded as a
component of revenue, hedging transactions for fuel used in energy generation are recorded as a component of fuel costs and
interest rate hedging transactions are recorded as a component of interest expense. SPS is allowed to recover in electric rates
the costs of certain financial instruments purchased to reduce commodity cost volatility. There was an immaterial amount of
hedge ineffectiveness in the third quarter of 2007.
The impact of qualifying cash flow hedges on SPS’ Accumulated Other Comprehensive Income, included as a component of
common stockholders’ equity, are detailed in the following table:
Nine months ended Sept. 30,
(Millions of dollars) 2007 2006
Accumulated other comprehensive loss related to cash flow hedges at Jan. 1 ........................... $ (5.9 ) $ (4.8)
After-tax net unrealized gains related to derivatives accounted for as hedges............................ 0.1 —
After-tax net realized losses on derivative transactions reclassified into earnings ..................... 0.2 0.2
Accumulated other comprehensive loss related to cash flow hedges at Sept. 30........................ $ (5.6 ) $ (4.6)

Derivatives Not Qualifying for Hedge Accounting
SPS enters into certain commodity-based derivative transactions, not included in trading operations, which do not qualify for
hedge accounting treatment. These derivative instruments are accounted for on a mark-to-market basis in accordance with
SFAS 133. The results of these transactions are reported in the Statements of Income.
Normal Purchases or Normal Sales Contracts
SPS enters into contracts for the purchase and sale of various commodities for use in its business operations. SFAS 133
requires a company to evaluate these contracts to determine whether the contracts are derivatives. Certain contracts that meet
the definition of a derivative may be exempted from SFAS 133 as normal purchases or normal sales.
SPS evaluates all of its contracts when such contracts are entered to determine if they are derivatives and, if so, if they qualify
and meet the normal designation requirements under SFAS 133. None of the derivative contracts entered into within the
commodity trading operations qualify for a normal designation.
9. Detail of Interest and Other Income, Net
Interest and other income, net of nonoperating expenses, for the three and nine months ended Sept. 30 consisted of the
following:
Three months ended Nine months ended
Sept. 30, Sept. 30,
(Thousands of dollars) 2007 2006 2007 2006

Interest income................................................ $ 730 936 $ 2,184 $ 2,888
Other nonoperating income ............................ 158 64 205 895
Other nonoperating expense ........................... (54) (13) (225) (128)
Total interest and other income, net............ $ 834 $ 987 $ 2,164 $ 3,655

10. Segment Information
SPS has one reportable segment. SPS operates in the Regulated Electric Utility industry, providing wholesale and retail
electric service in the states of Texas and New Mexico. Revenues from external customers were $1,238.5 million and
$1,308.6 million for the nine months ended Sept. 30, 2007 and 2006, respectively.

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11. Comprehensive Income
The components of total comprehensive income are shown below:
Three months ended Nine months ended
Sept. 30, Sept. 30,
(Millions of dollars) 2007 2006 2007 2006
Net income.............................................................. $ 21.2 $ 32.6 $ 28.4 $ 54.5
Other comprehensive income:
After-tax net unrealized gains (losses) related to
derivatives accounted for as hedges (see Note 8) (0.4) (0.6) 0.1 —
After-tax net realized losses on derivative
transactions reclassified into earnings
(see Note 8)......................................................... 0.1 0.1 0.2 0.2
Other comprehensive income ................................. (0.3) (0.5) 0.3 0.2
Comprehensive income........................................... $ 20.9 $ 32.1 $ 28.7 $ 54.7
12. Benefit Plans and Other Postretirement Benefits
Pension and other postretirement benefit disclosures below generally represent Xcel Energy consolidated information unless
specifically identified as being attributable to SPS.
Components of Net Periodic Benefit Cost
Three months ended Sept. 30,
2007 (1) 2006 2007 2006
Postretirement Health
Care Benefits
(Thousands of dollars) Pension Benefits
Xcel Energy Inc.
Service cost............................................................. $ 15,520 $ 15,406 $ 1,453 $ 1,659
Interest cost............................................................. 41,313 38,854 12,619 13,234
Expected return on plan assets................................ (66,208) (67,017) (7,600 ) (6,690)
Amortization of transition obligation...................... — — 3,644 3,611
Amortization of prior service cost (credit).............. 6,487 7,424 (545 ) (544)
Amortization of net loss.......................................... 4,211 4,339 3,550 6,200
Net periodic benefit cost (credit) ............................ 1,323 (994) 13,121 17,470
Credits not recognized due to the effects of
regulation ............................................................ 2,787 3,159 — —
Additional cost recognized due to the effects of
regulation ............................................................ — — 972 972
Net benefit cost recognized for financial
reporting.......................................................... $ 4,110 $ 2,165 $ 14,093 $ 18,442
SPS
Net benefit cost (credit) recognized for financial
reporting.............................................................. $ (1,909) $ (1,734) $ 1,560 $ 1,676

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Nine months ended Sept. 30,
2007 (1) 2006 2007 2006
Postretirement Health
Care Benefits
(Thousands of dollars) Pension Benefits
Xcel Energy Inc.
Service cost............................................................. $ 46,560 $ 46,220 $ 4,359 $ 4,975
Interest cost............................................................. 123,939 116,560 37,857 39,704
Expected return on plan assets................................ (198,624) (201,049) (22,800 ) (20,068)
Amortization of transition obligation...................... — — 10,932 10,833
Amortization of prior service cost (credit).............. 19,461 22,272 (1,635 ) (1,634)
Amortization of net loss.......................................... 12,633 13,015 10,650 18,598
Net periodic benefit cost (credit) ............................ 3,969 (2,982) 39,363 52,408
Credits not recognized due to the effects of
regulation ............................................................ 8,361 9,477 — —
Additional cost recognized due to the effects of
regulation ............................................................ — — 2,918 2,918
Net benefit cost recognized for financial
reporting.......................................................... $ 12,330 $ 6,495 $ 42,281 $ 55,326
SPS
Net benefit cost (credit) recognized for financial
reporting.............................................................. $ (5,728) $ (5,796) $ 4,679 $ 5,029

(1) Includes qualified and non-qualified pension net periodic benefit cost.

Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS

Discussion of financial condition and liquidity for SPS is omitted per conditions set forth in general instructions H (1) (a) and
(b) of Form 10-Q for wholly owned subsidiaries. It is replaced with management’s narrative analysis and the results of
operations set forth in general instructions H (2) (a) of Form 10-Q for wholly owned subsidiaries (reduced disclosure format).

Forward-Looking Information

The following discussion and analysis by management focuses on those factors that had a material effect on the financial
condition and results of operations of SPS during the periods presented, or are expected to have a material impact in the
future. It should be read in conjunction with the accompanying unaudited financial statements and notes.

Except for the historical statements contained in this report, the matters discussed in the following discussion and analysis are
forward-looking statements that are subject to certain risks, uncertainties and assumptions. Such forward-looking statements
are intended to be identified in this document by the words “anticipate,” “believe,” “estimate,” “expect,” “intend,” “may,”
“objective,” “outlook,” “plan,” “project,” “possible,” “potential,” “should” and similar expressions. Actual results may vary
materially. Forward-looking statements speak only as of the date they are made, and we do not undertake any obligation to
update them to reflect changes that occur after that date. Factors that could cause actual results to differ materially include,
but are not limited to: general economic conditions, including the availability of credit and its impact on capital expenditures
and the ability of SPS to obtain financing on favorable terms; business conditions in the energy industry; actions of credit
rating agencies; competitive factors, including the extent and timing of the entry of additional competition in the markets
served by SPS; unusual weather; effects of geopolitical events, including war and acts of terrorism; state, federal and foreign
legislative and regulatory initiatives that affect cost and investment recovery, have an impact on rates or have an impact on
asset operation or ownership; structures that affect the speed and degree to which competition enters the electric market; costs
and other effects of legal and administrative proceedings, settlements, investigations and claims; actions of accounting
regulatory bodies; the items described under Factors Affecting Results of Continuing Operations; and the other risk factors
listed from time to time by SPS in reports filed with the SEC, including “Risk Factors” in Item 1A of SPS’ Form 10-K for the
year ended Dec. 31, 2006 and Exhibit 99.01 to this report on Form 10-Q for the quarter ended Sept. 30, 2007.

Market Risks

SPS is exposed to market risks, including changes in commodity prices and interest rates, as disclosed in Item 7A —
Quantitative and Qualitative Disclosures About Market Risk in its Annual Report on Form 10-K for the year ended Dec. 31,
2006. Commodity price and interest rate risks for SPS are mitigated in most jurisdictions due to cost-based rate regulation. At
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Sept. 30, 2007, there were no material changes to the financial market risks that affect the quantitative and qualitative
disclosures presented as of Dec. 31, 2006.

RESULTS OF OPERATIONS

SPS’ net income was approximately $28.4 million for the first nine months of 2007, compared with approximately $54.5
million for the first nine months of 2006. The decrease was due to lower electric margin, primarily as the result of accruals
for potential fuel contingencies, partially offset by lower property taxes, and lower income taxes as a result of the lower pre-
tax income.

Electric Utility, Short-term Wholesale and Commodity Trading Margins

Electric fuel and purchased power expenses tend to vary with changing retail and wholesale requirements and unit cost
changes in fuel and purchased power. Due to fuel and purchased energy cost recovery mechanisms for customers, most
fluctuations in these costs do not materially affect electric utility margin.

SPS has two distinct forms of wholesale sales: short-term wholesale and commodity trading. Short-term wholesale refers to
energy related purchase and sales activity and the use of certain financial instruments associated with the fuel required for
and energy produced from SPS’ generation assets and energy and capacity purchased to serve native load. Commodity
trading is not associated with SPS’ generation assets or the energy and capacity purchased to serve native load.

SPS conducts an inconsequential amount of commodity trading. Margins from commodity trading activity are partially
redistributed to Northern States Power Company, a Minnesota corporation, and Public Service Company of Colorado, both
wholly owned subsidiaries of Xcel Energy, pursuant to the joint operating agreement (JOA) approved by the FERC. Margins
received pursuant to the JOA are reflected as part of base electric utility revenues. Short-term wholesale and commodity
trading margins reflect the impact of regulatory sharing, if applicable. Commodity trading revenues are reported net of
trading costs (i.e., on a margin basis) in the Statements of Income. Commodity trading costs include purchased power,
transmission, broker fees and other related costs.

The following table details base electric utility and short-term wholesale activities:

Base
Electric Short-Term Commodity
Wholesale Trading
(Millions of Dollars) Utility Total
Nine months ended Sept. 30, 2007
Electric utility revenues (excluding commodity
trading)....................................................................... $ 1,220 $ 19 $ —$ 1,239
Fuel and purchased power ............................................. (882) (18) — (900)
Commodity trading revenues......................................... — — — —
Commodity trading costs ............................................... — — — —
Gross margin before operating expenses ................... $ 338 $ 1$ —$ 339
Margin as a percentage of revenues............................... 27.7% 5.3% —% 27.4%

Nine months ended Sept. 30, 2006 ..............................
Electric utility revenues (excluding commodity
trading)....................................................................... $ 1,302 $ 6$ —$ 1,308
Fuel and purchased power ............................................. (932) (6) — (938)
Commodity trading revenues......................................... — — 1 1
Commodity trading costs ............................................... — — (1 ) (1)
Gross margin before operating expenses ................... $ 370 $ —$ —$ 370
Margin as a percentage of revenues............................... 28.4% —% —% 28.3%

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The following summarizes the components of the changes in base electric revenues and base electric margin for the nine
months ended Sept. 30:

Base Electric Revenues

(Millions of dollars) 2007 vs. 2006
Fuel and purchased power cost recovery ............................. $ (78)
SPS potential regulatory settlements ................................... (14)
Retail sales decline (excluding weather impact).................. (3)
Estimated impact of weather................................................ (1)
Firm wholesale..................................................................... 8
Transmission revenue .......................................................... 6
Total decrease in base electric revenues .......................... $ (82)

Base Electric Margin

SPS potential regulatory settlements ................................... $ (14)
Purchased capacity costs...................................................... (9)
Fuel handling and procurement ........................................... (9)
Retail sales decline (excluding weather impact).................. (3)
Estimated impact of weather................................................ (1)
Firm wholesale..................................................................... 7
Other .................................................................................... (3)
Total decrease in base electric margin ............................. $ (32)

Non-Fuel Operating Expense and Other Costs

Other Operating and Maintenance Expenses - The following summarizes the components of the changes in other operating
and maintenance expense for the nine months ended Sept. 30:

Higher combustion/hydro plant costs ................................. $ 7
Higher labor costs ............................................................... 1
Higher uncollectible receivable costs ................................. 1
Higher material costs .......................................................... 1
Lower employee benefit costs ............................................ (2)
Other ................................................................................... 3
Total increase in other operating and maintenance
expenses...................................................................... $ 11

Taxes (other than income taxes) - Taxes (other than income taxes) decreased by approximately $9.1 million, or 22.6 percent,
for the first nine months of 2007, compared with the first nine months of 2006. The decrease was primarily due to a reduction
in Texas property taxes and the discontinuation of the Texas franchise fee.

Income taxes - Income tax expense decreased by approximately $12.9 million for the first nine months of 2007 compared
with the first nine months of 2006. The decrease was primarily due to lower pretax income. The effective tax rate was 40.6
percent for the first nine months of 2007, compared with 37.3 percent for the same period in 2006. The increase in the
effective tax rate was primarily due to an increase in the forecasted effective tax rate for 2007 as compared to 2006.

Regulation

Summary of Recent Federal Regulatory Developments

The FERC has jurisdiction over rates for electric transmission service in interstate commerce and electric energy sold at
wholesale, hydro facility licensing, accounting practices and certain other activities of SPS. State and local agencies have
jurisdiction over many of SPS’ activities, including regulation of retail rates and environmental matters. In addition to the
matters discussed below, see Note 4 to the financial statements for a discussion of other regulatory matters.

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FERC Rules Implementing Energy Policy Act of 2005 (Energy Act) — The Energy Act repealed the Public Utility Holding
Company Act of 1935, effective Feb. 8, 2006. In addition, the Energy Act required the FERC to conduct several rulemakings
to adopt new regulations to implement various aspects of the Energy Act. Since Aug. 2005, the FERC has completed or
initiated proceedings to modify its regulations on a number of subjects. In addition to the previous disclosure in Item 1 of
SPS’ Form 10-K for the year ended Dec. 31, 2006, the FERC issued final rules making certain reliability standards
mandatory and subject to potential financial penalties up to $1 million per day per violation for non-compliance effective
June 18, 2007.

While SPS cannot predict the ultimate impact the new regulations will have on its operations or financial results, SPS is
taking actions that are intended to comply with and implement these new rules and regulations as they become effective.

Electric Transmission Rate Regulation — The FERC also regulates the rates charged and terms and conditions for electric
transmission services. FERC policy encourages utilities to turn over the functional control over their electric transmission
assets and the related responsibility for the sale of electric transmission services to a RTO. SPS is a member of the SPP. Each
RTO separately files regional transmission tariff rates for approval by the FERC. All members within that RTO are then
subjected to those rates.

On Feb. 15, 2007, the FERC issued final rules adopting revisions to its 1996 open access transmission rules. SPS submitted
the initial required revisions to its Open Access Transmission Tariff (OATT) on July 13, 2007 and Sept. 11, 2007, as
required.

In addition, in January 2007, the FERC issued interim and proposed rules to modify the current FERC rules governing the
functional separation of the SPS electric transmission function from the wholesale sales and marketing function. The
proposed rules are pending final FERC action.

While SPS cannot predict the ultimate impact the new regulations will have on its operations or financial results, SPS is
taking actions that are intended to comply with and implement these new rules and regulations as they become effective.

Market Based Rate Rules — On June 21, 2007, the FERC issued a final order amending its regulations governing its market-
based rate authorizations to electric utilities such as SPS. The FERC reemphasized its commitment to market-based pricing,
but is revising the tests it’s using to assess whether a utility has market power and has emphasized that it intends to exercise
greater oversight where it has market-based rate authorizations. SPS has been granted market-based rate authority and will be
subject to the new rule. SPS is presently analyzing the new rule.

An aspect of FERC’s market-based rate requirements is the requirement to charge mitigated rates in markets where a utility is
found to have market power or where a utility cannot establish the absence of market power. SPS has been authorized by the
FERC to charge market-based rates outside of their control areas, but is generally limited to charging mitigated rates within
their control areas. Consistent with the approach followed by many other utilities subject to the FERC’s mitigation
requirement, SPS uses cost-based rate caps set out in the Western Systems Power Pool (WSPP) agreement as their applicable
mitigated rates, an approach expressly approved by the FERC. However, concurrently with the issuance of the final order, the
FERC initiated a proceeding to investigate whether the use of the WSPP rate caps for this purpose is just and reasonable. An
outcome of this proceeding may be to lower the mitigated rates that SPS may charge in their control areas.

Other Regulatory Matters — SPS

New Mexico Renewable Portfolio Standard - The 2007 New Mexico legislature enacted a renewable portfolio standard in
which renewable energy must comprise no less than 5 percent of retail sales by 2006; 10 percent by 2011; 15 percent by
2015; and 20 percent by 2020. The legislation also allows performance-based incentives to encourage the acquisition of
renewable energy supplies beyond the requirements. The NMPRC has implemented revised rules related to the increased
requirements. The NMPRC has interpreted the diversification requirement to mean no less than 20 percent of the standard is
met using wind energy, no less than 20 percent using central solar, no less than 10 percent other (e.g., biomass, geothermal),
and no less than 1.5 percent using renewable distributed generation (increasing to 3 percent by 2015). The effective date of
the diversification requirements is 2011.

Texas Renewable Energy Zones - The PUCT designated competitive renewable energy zones (CREZs) this summer. CREZs
are regions of the state in which renewable energy resources and suitable land areas are sufficient to develop electric
generating capacity from renewable energy technologies, such as wind. Several CREZ areas within the SPS service region
were designated for potential development. The PUCT considered the availability of renewable resources in a candidate
CREZ, the financial commitment of generators and the major transmission improvements necessary to deliver the energy

19

generated by renewable resources. A statewide study conducted by the Electric Reliability Council of Texas (ERCOT)
identifies the Texas panhandle as having the top four of the state’s primary areas for wind energy expansion. Several
transmission proposals have been filed in the CREZ proceeding, including plans to interconnect CREZs with the SPP and
plans that would collect wind energy from panhandle CREZs and deliver it into ERCOT.

Texas Retail Base Rate And Fuel Reconciliation Case - As more fully described in Note 4 to the financial statements, on
July 27, 2007, the PUCT issued a written order adopting a settlement, which in part provided for an annual base rate increase
of $23 million. However, this rate increase will not have a material effect on the financial statements due to differences in
certain assumptions used in developing the test year revenue requirement versus actual performance. The changes are related
largely to assumptions associated with firm versus interruptible customer loads and the appropriate demand billing
determinants when converting a rate structure based primarily on energy charges to one based primarily on demand charges.

Item 4. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

SPS maintains a set of disclosure controls and procedures designed to ensure that information required to be disclosed in
reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported
within the time periods specified in Securities and Exchange Commission rules and forms. In addition, the disclosure controls
and procedures ensure that information required to be disclosed is accumulated and communicated to management, including
the chief executive officer (CEO) and chief financial officer (CFO), allowing timely decisions regarding required disclosure.
As of the end of the period covered by this report, based on an evaluation carried out under the supervision and with the
participation of SPS’ management, including the CEO and CFO, of the effectiveness of our disclosure controls and
procedures, the CEO and CFO have concluded that SPS’ disclosure controls and procedures are effective.

Internal Control Over Financial Reporting

No change in SPS’ internal control over financial reporting has occurred during the most recent fiscal quarter that has
materially affected, or is reasonably likely to materially affect, its internal control over financial reporting.

Part II. OTHER INFORMATION

Item 1. Legal Proceedings

In the normal course of business, various lawsuits and claims have arisen against SPS. Management, after consultation with
legal counsel, has recorded an estimate of the probable cost of settlement or other disposition for such matters. See Notes 4
and 5 of the Financial Statements in this Quarterly Report on Form 10-Q for further discussion of legal proceedings,
including Regulatory Matters and Commitments and Contingent Liabilities, which are hereby incorporated by reference.
Reference also is made to Item 3 and Note 11 of SPS’ Annual Report on Form 10-K for the year ended Dec. 31, 2006 for a
description of certain legal proceedings presently pending.

Item 1A. Risk Factors

SPS’ risk factors are documented in Item 1A of Part I of its 2006 Annual Report on Form 10-K, which is incorporated herein
by reference. There have been no material changes to the risk factors.

Item 6. Exhibits

The following Exhibits are filed with this report:

31.01 Principal Executive Officer’s and Principal Financial Officer’s certifications pursuant to 18 U.S.C. Section 1350, as
adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
32.01 Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of
2002
99.01 Statement pursuant to Private Securities Litigation Reform Act of 1995.

20

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed
on its behalf by the undersigned thereunto duly authorized on Oct 29, 2007.

Southwestern Public Service Co.
(Registrant)

/s/ TERESA S. MADDEN
Teresa S. Madden
Vice President and Controller

/s/ BENJAMIN G.S. FOWKE III
Benjamin G.S. Fowke III
Vice President and Chief Financial Officer

21

xcel energy SPS_10Q_2007_Q3

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